Rotatably-Actuated Fluid Treatment System Using Coiled Tubing

ABSTRACT

A system for treating a formation of a borehole having casing has a sleeve, a motor, and a packer. The sleeve is disposed on the casing in the borehole and has a port communicating out of the sleeve. An insert disposed in the sleeve is movable in the sleeve from closed to opened position relative to the port. The motor is deployed in the casing with coiled tubing and is operable to impart rotation. The packer is operatively coupled to the motor. In response to the rotation imparted by the motor, the packer sets in the insert of the sleeve and moves the insert to the opened condition.

BACKGROUND OF THE DISCLOSURE

With advancements in the industry, packers deployed with coiled tubingand used with sliding sleeves are becoming a preferred method oftreating lateral wells. With that said, several techniques have beendeveloped for treating zones of lateral well with these components.

Referring to FIG. 1, for example, a fracturing system 10 of the priorart uses coiled tubing 24, sliding sleeves 30A-C, a packer 40, and ashifting tool 45. Although shown as vertical, the borehole 12 can be,and most likely is, a horizontal or deviated borehole. A casing or liner14 is cemented in the borehole 12 using standard procedures so cement 16supports the casing 14 in the borehole 12. At suitable zones along theborehole 12, the sliding sleeves 30A-C are cemented in place along thecasing 14 in closed conditions.

The system 10 is similar to a ZoneSelect coiled tubing (CT) systemavailable from Weatherford International Ltd. The system 10 enablesaccess to individual zones in the reservoir with thecoiled-tubing-actuated sleeves 30A-C and with the packer 40 and shiftingtool 45 on the single coiled-tubing bottomhole assembly (BHA). In thesystem 10, the sleeves 30A-C are actuated using the coiled tubing 24 andthe shifting tool 45. The resettable coiled-tubing packer 40 is then setbelow the sleeve 30A-C, and the zone is stimulated while the coilremains in the well.

To begin a fracture operation, for example, operators deploy the packer40 and shifting tool 45 on coiled tubing 24 down the casing 14. Theshifting tool 45 is deployed inside an insert of the lower slidingsleeve 30A, and operators pull up on the tubing 24 to open the insert onthe sleeve 30A to expose external ports.

Operators then run the packer 40 into the joint below the open sleeve30A and set the packer 40 hydraulically. At this point, operatorsperform annular fracture operations by pumping fluid down the annulusbetween the casing 14 and the coiled tubing 24 so that the fracturefluid exits ports on the open sleeve 30A and treats the surroundingformation through perforations 15, cracks, fissures, exposed areas, etc.

This process is repeated for all the sleeves 30A-C in the well from thetoe to the heel of the completion. If needed, a sand jet perforator (notshown) can be used to create additional zones. At the conclusion of thetreatment, the coiled tubing 24 is pulled out of the well, leaving amonobore completion that can be used directly for production. The system10 eliminates the need for milling operations after the stimulation,which could damage sensitive reservoirs.

Another system 10 illustrated in FIG. 2 uses coiled tubing 24, aresettable plug 50/70, and sliding sleeves 40/60, but the sleeves 40/60are not shifted open mechanically with a shifting tool as before.Instead, different operations are performed to open the sliding sleeves40/60 so that fluid can be communicated out of the casing 14 and intothe formation surrounding the borehole 12.

In particular, FIG. 3A illustrates one example for the system 10 in FIG.2 that uses coiled tubing 24, an isolation assembly 50, and a slidingsleeve 40. This example system is similar to that disclosed inUS2013/0180721. The coiled tubing 24 deploys the isolation assembly 50to the sliding sleeve 40 and opens the sleeve 40 using coiled tubingmanipulation and applied pressure while the isolation assembly 50 is setinside the sliding sleeve 40.

In particular, the sleeve 40 is disposed on the casing (14) at apredetermined point where the formation is to be treated, and the sleeve40 is cemented in the borehole along with the rest of the casing 14.When treatment is to be performed, the isolation assembly 50 disposed onthe coiled tubing 24 deploys to the sleeve 40 to be opened. Theisolation assembly 50 includes a treatment housing 51 with ports 56, asand-jet perforating sub 58 with nozzles 59, an equalizing valve (notshown), a resettable plug 54, and a sleeve locator 52. A ball valve (notshown) is disposed between the first treatment housing 51 and jetperforation sub 58 for selecting output of fluid from the assembly 50.

The resettable plug 54 isolates the zone from the casing 14 below,mechanically shifts the sleeve 40 open, and anchors the isolationassembly 50 during fracture pumping. An automatic J-slot mechanism (notshown) sets, releases, and resets the assembly 50 with straight up/downcoiled tubing motion. The integral equalization valve (not shown)facilitates releasing the plug 54, and the sand-jet perforating sub 58can be used to add a stage in a blank section of the casing 14.

To fracture the formation, for example, the assembly 50 deploys as partof the coiled tubing 24 and positions below the sliding sleeve 40. Theassembly 50 is then pulled upward, and the keys of the sleeve locator 52engage a recess 46 at the end of the sleeve 40. The keys on the locator52 snap into the recess 46, which gives a positive indication that theassembly 50 is properly positioned. Coiled tubing set-down weight thensets the resettable plug 54. The plug's slips grip inside the sleeve'sinsert 42, and the plug's packer element seals against the sleeve'sinsert 42 to seal off the lower casing 14. Operators increase pressurein the casing 14 and force the assembly 50 and the insert 42 down withthe pressure, which opens the sleeve's ports 44 to the formation. Whenthe insert 42 shifts, the recess 46 closes and forces the locator 52 toretract, indicating that the sleeve 50 has shifted open.

Operators pump fracture treatment down the annulus between the coiledtubing 24 and casing 14, although the fluid can be pumped through thecoiled tubing 24 for lower rates. For example, fracturing fluid can beapplied through the coiled tubing 24, exiting first ports 56 present intreatment housing 51 and resulting in the fracturing of the regionaround the sleeve's ports 44. Once the fluid has been pumped, operatorspull on the coiled tubing 24 to open the integral equalizing valve (notshown) and unset the plug 54. The isolation assembly 50 can then bemoved up to the next sleeve 40 so the sequence can be repeated for a newzone.

To add a stage, the isolation assembly 50 can be set in a blank sectionof the casing 14, and a perforation can be made. To do this, a ball canbe dropped to prevent fluid flow down to the treatment housing 51. Thisresults in fluid diversion to the nozzles 59 of the jet perforation sub58. Operators pump sand-laden fluid down the coiled tubing 24 and outthe nozzles 59 of the perforating sub 58 to cut through the casing 14and cement and into the formation.

FIG. 3B illustrates a sliding sleeve 40 as disclosed in US 2012/0090847,which can be used with the system and assembly 50 of FIG. 3A. Asspecifically shown in FIG. 3B, a similar type of assembly 50 can also beused to mechanically shift the sliding sleeve 40. As depicted here, acasing collar locator 52 engages a corresponding profile 46 below theunshifted insert 42 within the ported sleeve 40. Once the collar locator52 is engaged, a plug or seal 54 is set against the insert 42, aided bymechanical slips 55. When set, the seal 42 isolates the wellbore abovethe ported sleeve 40.

To open the sleeve 40, force and/or hydraulic pressure are applied tothe work string (not shown) and packer 54 from uphole. The force and/orhydraulic pressure shears a shear pin 49 and shifts the insert 42downward so that it engages the locator (52). As the sleeve's insert 42shifts downhole, the collar locator 52 collapses, and the insert 42exposes the ports 44 in the sleeve 40.

The applied force and/or pressure to open the insert 42 may be amechanical force applied directly to the work string (and thereby to theengaged insert 42) from the surface, for example, using coiled tubing,jointed pipe, or other tubing string. The applied force and/or pressureto open the insert 42 may also be a hydraulic pressure applied againstthe seal 54 through the wellbore annulus and/or through the work string.

Once the ports 44 are open, treatment may be applied to the formation.For example, fracturing fluid can be applied through the coiled tubing24, exiting ports 56 present in the assembly 50 to fracture the regionaround the sleeve's ports 44. After the sleeve 40 has been opened, theseal 54 and work string may remain set within the wellbore to isolatethe ports 44 in the newly opened sleeve 40 from any previously openedports below. Alternatively, the seal 54 may be unset for verifying thestate of the opened sleeve 40, or to relocate the work string asnecessary (for example to apply treatment fluid to the ports of one ormore sleeves 40 simultaneously).

Depending on the configuration of the work string, treatment fluid maybe applied to the ports 44 through one or more apertures in the assembly50 or the work string, or via the wellbore annulus about the workstring. If perforation is desired in a region of the casing 14 above thesleeve's ports 44, a ball can be dropped to prevent fluid flow down tothe lower ports 56. This results in fluid diversion to the nozzles 59 ofthe assembly 50.

FIG. 3C illustrates another sliding sleeve 40 as disclosed in US2012/0090847. This sleeve 40 has an annular channel 47 that extendslongitudinally within the sleeve 40 between inner and outer housings 48a-b and intersects treatment ports 44. A valve 45 within the channel 47is held over the treatment ports 44 by a shear pin 49. The channel 47 isopen to the inner bore near each end at sleeve ports 41, 43. The valve45 is generally held or biased to the closed position covering the port44, but may be slidably actuated within the channel 47 to open thetreatment port 44. For example, a seal (not shown) of an assembly may bepositioned in the housing 48 a between the sleeve ports 41, 43 to allowapplication of fluid to the upper sleeve port 41 (without correspondingapplication of hydraulic pressure through the lower sleeve port 43). Asa result, the valve 45 slides within the channel 47 toward the opposingsleeve port 43, thereby opening the treatment port 44. Treatment maythen be applied to formation through the port 44.

Compared to the systems of FIGS. 3A-3C, a similar system shown in FIG.4A also uses coiled tubing 24, an isolation assembly 70, and slidingsleeves 60. This system is disclosed in US Pat. Pub. No. 2011/0308817.As shown, the sleeve 60 has ports 64 for fluid communication outside thesleeve 60. An insert 62 positioned in the sleeve 60 can be moved from aclosed position to an opened position and can be held in the closedposition with a shear pin 63.

The assembly 70 connects to the coiled tubing 24 and positions insidethe sliding sleeve 60. A casing collar locator 72 may be used to locatethe assembly 70 in the sleeve 60. For example, a lower cross-overattached to the sleeve 60 may include a profile 66 to engage the casingcollar locator 72.

The assembly 70 has a packer 74 that may be activated to seal theannulus between the assembly 70 and the sleeve's insert 62. The assembly70 also includes an anchor 75 that may be set against the insert 62.Application of pressure down the coiled tubing 24 activates the packer74 and the anchor 75 and sets them against the insert 62.

After setting the packer 74 and the anchor 75, fluid pumped down thecasing 14 creates a pressure differential across the packer 74. When apredetermined pressure differential is reached, the shear pin 63 shearsand releases the insert 62 from the sleeve 60. The increased pressuredifferential across the packer 74 then moves the assembly 70 anchored tothe insert 62 down the sleeve 60. In this way, the insert 62 can bemoved from the closed position to the open position. After the insert 62has been opened, the assembly 70 may be released, moved up the casing 14to the next desired zone, and set within another sleeve 60 as before.

Yet another similar system shown in FIG. 4B also uses coiled tubing (notshown), an isolation assembly 70, and a sliding sleeve 60. This systemis also disclosed in US Pat. Pub. No. 2011/0308817 and is similar towhat is disclosed in SPE 143250, entitled “Cased-Hole Multi-StageFracturing: A new Coiled Tubing Enabled Completion” by JohnRavensbergen. The fracture sleeve 60 is a pressure-balanced device thatopens when subjected to a pressure differential. As shown, the sleeve 60has ports 64, vent holes 63 a-b, and a valve 65, which can be moved froma closed to an opened position.

As before, the sleeve 60 is run as part of the casing 14 cemented in theborehole. As specifically shown in FIG. 4B, the sleeve 60 made up to thecasing 14 has a mandrel 61 a, a valve housing 61 b, and a vent housing61 c. The valve 65 is positioned within an annulus 67 between themandrel 61 a and the valve housing 61 b. The sleeve 65 is movable to anopen position (shown in FIG. 4B) that permits communication out of themandrel 61 a through ports 64. In a closed position, the valve 65 isheld by the shear pin 69. The mandrel 61 a may include one or more ports63 a that are positioned uphole of the closed valve 65 to aid in theapplication of a pressure differential into the annulus 67 above thevalve 65 when moving the valve 65 to the open position.

To fracture the formation adjacent the sleeve 60, the assembly 70 ispositioned in the sleeve 60 while the pressure balanced valve 65 isinitially closed. A casing collar locator (not shown) can be used on theend of the assembly 70 to position the assembly 70 in the sleeve 60. Tocreate a pressure differential, an isolation packer 74 is set inside thesleeve 60 and pressure is applied from the surface in the casing 14 sothat a pressure differential is generated across the sleeve 60. When thedifferential exceeds a predetermined level, shear pin 69 breaks, and thevalve 65 shifts open.

As shown, the packer 74 can be positioned between the ports 63 a-b. Whenthe packer 74 is energized, it seals inside the sleeve 60 to preventfluid flow further downhole. Thus, when fluid flows downhole fromsurface in the annulus between the casing 14 and the assembly 70, apressure differential is formed across the packer 74 between the ports63 a-b, which opens the valve 65. After opening the valve 65 andfracturing the wellbore, the valve 65 may be moved back to the closedposition upon the application of a reverse pressure differential.

As indicated above, a number of systems have been used for treatingzones of a formation with assemblies deployed on coiled tubing. Theseassemblies use mechanical shifting to open sliding sleeves (e.g.,FIG. 1) or use packers and hydraulic pressure to open the slidingsleeves (e.g., FIGS. 2 through 4B). Although such systems are useful,some problems still remain. For example, the sliding sleeves can bedeployed as port collars on the casing in the borehole and may becemented in place. Under these conditions, opening the sliding sleevesmay be complicated by residual cement.

Additionally, some of the systems require weight to be available at theend of the coiled tubing so the available weight can be used to initiatesetting of a packer, shifting the sleeve, or some other operation.Because the coiled tubing may be deployed in a deviated of horizontalwell, an overwhelming amount of sinusoidal and helical buckling mayoccur in the coiled tubing, which minimizes the functionality of thesystem at the toe of the well. Historically, the ability to reachextended horizontal length has been gained by circulating down frictionreducing agents, using mechanical agitators to break friction, etc. Yeteven with such extended reach, the capabilities at the end of the coiledtubing may still be limited.

What is needed is a system that can reliably reach and function atextended lengths in a horizontal well. The subject matter of the presentdisclosure is directed to overcoming, or at least reducing the effectsof, one or more of the problems set forth above.

SUMMARY OF THE DISCLOSURE

A system is used for treating a formation of a borehole having casing.The system has a sleeve, a motor, and a packer. The sleeve is disposedon the casing in the borehole and has a port communicating out of thesleeve. An insert disposed in the sleeve is movable in the sleeve fromclosed to opened positions relative to the port. The motor is deployedin the casing with coiled tubing and is operable to impart rotation. Thepacker is operatively coupled to the motor. In response to the rotationimparted by the motor, the packer sets in the insert of the sleeve andmoves the insert to the opened condition.

The foregoing summary is not intended to summarize each potentialembodiment or every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a first fracturing system according to the prior artusing a packer and shifting tool on coiled tubing for manipulatingsliding sleeves.

FIG. 2 illustrates a second fracturing system according to the prior artusing an isolation assembly on coiled tubing for manipulating slidingsleeves.

FIG. 3A illustrates a prior art system as in FIG. 2 that uses coiltubing, an isolation assembly, and a sliding sleeve.

FIG. 3B illustrates a prior art sliding sleeve for the system as in FIG.2.

FIG. 3C illustrates another prior art sliding sleeve for the system asin FIG. 2.

FIG. 4A illustrates another prior art system as in FIG. 2 that uses coiltubing, an isolation assembly, and a sliding sleeve.

FIG. 4B illustrates yet another prior art system as in FIG. 2 that usescoil tubing, an isolation assembly, and a sliding sleeve.

FIG. 5 illustrates a fracturing system according to the presentdisclosure using a resettable packer and a motor on coiled tubing formanipulating sliding sleeves.

FIGS. 6A-6B illustrate a motor and a packer for use on the coiled tubingin the disclosed fracturing system.

FIGS. 7A-7B illustrate a sleeve according to the present disclosure inclosed and open conditions.

FIGS. 8A-8C illustrate guide components for the inserts in the slidingsleeves of the present disclosure.

FIG. 9A-9D illustrate operational stages of the disclosed system.

DETAILED DESCRIPTION OF THE DISCLOSURE

Referring to FIG. 5, a fluid treatment system 10 of the presentdisclosure is illustrated in a borehole 12. The fluid treatment system10 can be a fracturing system for fracturing a formation, can be a steaminjection system, or can be any other type of fluid treatment systemknown and used in the art. Although the borehole 12 is shown as beingvertical, the borehole 12 can be, and most likely is, a horizontal ordeviated borehole. A casing or liner 14 is cemented in the borehole 12using standard procedures so cement 16 supports the casing 14 in theborehole 12. At suitable zones along the borehole 12, sliding sleeves orport collars 100A-C are disposed in closed conditions on the casing 14.When the casing 14 is cemented, these sleeves 100A-C are cemented inplace along with the casing 14.

To perform a treatment (fracture) operation, operators deploy anassembly having a motor 130 and a packer 150 on coiled tubing 24 downthe casing 14 to selectively open the sliding sleeves 100A-C. As will bedescribed in more detail below, the packer 150 is deployed inside one ofthe sleeves 100A to be set therein. Operators start a pump in a pumpingsystem 22 at the surface to operate the downhole motor 130, whichrotates and sets the packer 150 in the given sleeve 100A. As the setpacker 150 continues to rotate, the sleeve 100A opens from a closedposition to an opened position. Once the sleeve 100A is open, the packer150 can then remain in the sleeve 100A or can be unset and movedelsewhere.

Either way, the pumping system 22 pumps a treatment fluid to treat theformation through the opened sleeve 100A. The treatment can be pumpeddown the casing 14 in the annulus around the coiled tubing 24 or can bepumped down the coiled tubing 24. This process of opening sleeves 100A-Cand treating the formation is repeated in the casing 14 to treat thevarious zones. Of course, because the sliding sleeves 100A-C can beselectively opened, treatment of the various zones can be performed inany desired order or combination.

At some point during operations, flow through the coiled tubing 24 mayneed to be diverted so that it does not reach the motor 130 and packer150. For example, treatment fluid can be pumped through the coiledtubing 24, if desired. For this reason, a sequencing valve (170) can berun above the motor 130. The flow needed to operated the sequencingvalve (170) can be several times the flow required to operate the motor130 so that at high flow rates the valve (170) opens and diverts flowaway from the motor 130. Additionally, because the coiled tubing 24 maybe deployed at an extended depth in horizontal or deviated wells, anagitator (180), such as available from Andergauge Drilling Systems, canbe run on the coiled tubing 24 to move the coiled tubing 24 foroperating in a borehole having extended reach. The type of agitator(180) used and its location in the system 10 can vary depending on theimplementation.

The system 10 may also include a jet cutting assembly (not shown) forperforating the casing 14 at a location in the borehole 12. Such a jetcutting assembly can be similar to those used in the art and may beselectively activated using any number of available techniques. Thesystem 10 may also include a casing cutter (not shown) to create a newzone or open the casing 14 when a sleeve fails. Such a casing cutter canbe operated with the motor's rotation and may be selectively activatedusing any number of available techniques.

The system 10 eliminates the need for any weight at the toe of the well.The system 10 can still employ all of the known methods for extendingthe coiled tubing 24 out as far as possible in an extended reach well.However, the necessary weight needed to initiate setting of the packer150 and shifting of the sleeves 100A-C is not needed in the disclosedsystem 10.

With the benefit of the above overview of the system 10, its components,and its operation, discussion now turns to further details of the motor130 and the packer 150 (with reference to FIGS. 6A-6B) and to furtherdetails of the sliding sleeve 100 (with reference to FIGS. 7A-7B).

Turning first to FIGS. 6A-6B, an assembly has the downhole motor 130 andthe packer 150 for use on the coiled tubing (24) in the disclosedsystem. The motor 130 is a downhole motor operated by the flow of fluidconveyed by the coiled tubing (24) to a power section 132 of the motor130. The packer 150 is a rotate-to-set type of packer and can be used toopening the sliding sleeve 100 and seal off fluid flow.

As examples, the coiled tubing 24 can be 2⅜″ coiled tubing. The motor130 can be similar to a type of milling motor conveyable on coiledtubing. For example, the motor 130 can be similar to 2⅛″ CTD motoravailable from Weatherford International Ltd. The max torque of such amotor may be 438 ft-lbs (594 N-m), and a max flow of such a motor can beup to 13.2 gallons/minute (50 LPM). The max tensile load can be 18,250lbs (81,180 N). The desired revolutions per minute (RPM) produced by themotor 130 may only need to be relatively low, such as from 5 to 10 RPM.These characteristics along with the revolutions per minute producedwith the motor 130 can be appropriately adjusted for the implementationso that the motor 130 is adapted to set and unset the packer 150 and toopen the sleeves 100A-C.

As shown in FIG. 6B, the power section 132 of the motor 130 can have arotor 133 a that rotates in a stator 133 b when fluid flows betweenthem. A transmission section 134 transfers the rotation from the powersection 132 to a drive mandrel 140, which is supported by a bearingsection 136 in the motor 130. Fluid flow from the motor's uphole end131, which couples to the coiled tubing (24) or other component, travelsthrough the power section 132 and the transmission section 134 andeventually enters a flow bore 142 of the mandrel 140—beyond whichextends the packer 150.

For its part, the rotate-to-set type packer 150 can be similar toWeatherford's Ultra-Lok packer or other type of Lok-set packer. Thepacker 150 is retrievable, and the packing element 156 is set bycompression. Preferably, rotation sets and releases the packer 150. Forexample, the packer 150 can have a mandrel 152 coupled to the drivemandrel 140 of the motor 130. Disposed on the mandrel 152, the packer150 can have a housing 155, a packing element 156, biased locators 157,and biased drag blocks or grips 158.

The packing element 156 is configured to set using the rotation from themotor 130. In particular, the biased locators 157 can be used to locatethe packer 150 in a sliding sleeve (100A-C). The mandrel 152 can berotated and includes external threads 153 on which a ratchet 154 ridesto move the housing 155 on the mandrel 152 to compress the packingelement 156. The biased drag blocks 158 can engage against a surroundingsidewall to prevent the housing 155 from rotating with the mandrel 152.Once set in the sleeve (100A-C), the packer 150 rotates the sleeve(100A-C) open, as discussed in more detail below. When set, the packer150 may also be capable of handling a suitable pressure rating (e.g.,8-KSI) for treatment to be applied. Releasing the packer 150 may requirepulling by the coiled tubing (24) while rotating, which can unset thepacking element 156 and release the packer 150.

Turning now to FIGS. 7A-7B, a sliding sleeve or port collar 100according to the present disclosure is shown in a closed condition (FIG.7A) and an open condition (FIG. 7B). The sleeve 100 installs in aconventional way on uphole and downhole sections of tubing or casing(14). The sleeve 100 has a housing 102 with a bore 104 passingtherethrough. An insert 110 is movable in the bore 104 relative to ports105 defined in the housing 102. When the insert 110 is in the closedcondition (FIG. 7A), flow out of the sleeve 100 through the ports 105 isprevented. When the insert 110 is in the opened condition (FIG. 7B), theports 105 can communicate fluid from the bore 104 outside the sleeve 100to treat the formation.

The sleeve 100 can also include various other conventional features. Forexample, detents (not shown) can be formed at positions in the bore 104for engaging lock tabs (not shown) on the insert 110. Seals 114 on theinsert 110 can seal off the exit ports 105 when the insert 110 is in theclosed condition (FIG. 7A). These and other conventional features may bepresent on the sleeve 100.

As best shown in the closed condition of FIG. 7A, an internal rotationalguide 106 is defined along a portion of the inside surface of thehousing's bore 104. A portion of the external surface of the insert 110has one or more external rotational guides 116 (e.g., a pin, a profile,a dog, etc.). The external guides 116 complement the internal guide 106and ride in the internal guide 106 so that rotation of the insert 110inside the bore 102 moves the insert 110 down along the internal guide106 to the opened condition (FIG. 7B).

As shown here, the internal guide 106 can be a female feature, such as aslot, a channel, a groove, a cam, a worm gear, or the like, that spiralshelically around the inside surface of the housing's bore 104. Theexternal guide 116 on the insert 110 can be a male feature, such as apin, a bearing, a dog, a profile, etc. on the insert 110 that can ridein the internal guide 106 as the insert 110 is engaged by the packer(150) and is rotated by the motor (130).

As shown in FIG. 7A, the insert 110 of the sleeve 100 preferably startsin the uphole, closed position. The sleeve 100 is installed having theinternal guide 106 packed with high-temperature, intumescent siliconeprior to installation. This can help protect the internal guide 106during cementing and other operations. Rotation of the insert 110 movesthe insert 110 in the sleeve 100 to the opened condition shown in FIG.7B.

As shown, the guides 106 and 116 lead the insert 110 to concurrentlyrotate and axially displace in the housing's bore 104. As onealternative, the insert 110 may merely move from a closed to an openposition by rotation imparted by the motor (130). Also, the insert 110may be opened by first rotation from the motor 130 and then by separateaxial displacement by applied pressure.

In the sliding sleeve 100 as shown, the ports 105 may be disposed upholeof the internal guide 106 inside the housing's bore 104. The reverse isalso possible where the insert 110 moves uphole in the sleeve's bore 104to open the ports 105 further downhole. In this case, setting andunsetting of the packer 150 during operations may need to be modified toaccommodate such a reverse arrangement.

FIGS. 8A-8C illustrate a number of examples for the internal andexternal guides 106 and 116 that can be used between the insert 110 andthe housing 102. In FIG. 8A, the internal guide 106 is a slot thatspirals helically around the inside surface of the housing's bore 104.The external guide 116 is a pin 117 a disposed on the external surfaceof the insert 110. Rotation of the insert 110 moves the pin 117 a in theslot 106 so that the rotation of the insert 110 is guided axially alongthe housing's bore 104.

In FIG. 8B, the internal guide 106 is again a slot that spiralshelically around the inside surface of the housing's bore 104. Theexternal guide 116 is a biased pin 117 ba disposed on the externalsurface of the insert 110. Additionally as shown in FIG. 8C, theinternal guide 106 is a bearing groove that spirals helically around theinside surface of the housing's bore 104, and the external guide 116 isa bearing 117 c disposed in a bearing detent on the external surface ofthe insert 110.

Although the internal guide 106 has been shown above as a female featureand the external guide 116 has been shown as a male feature, a reversearrangement can be used. For example, any of the various slots orbearing grooves shown in FIGS. 8A-8C above can be defined around theexterior surface of the insert 110, and any pins, bearings, and the likecan be disposed on the interior surface of the sleeve's bore 104.Moreover, an arrangement having mutually complementary features (i.e., athread) can be used. As will be appreciated, the length, pitch, andother aspects of the guides 106 and 116 can be adjusted for theparticular friction, RPMs, torque, and other specifications of a givenimplementation. In fact, rotation and axial displacement along theguides 106 and 116 can be coordinated with known rotation of the motor130 so that the insert 110 can be adjustably opened relative to theports 105. This can allow operators to vary the amount of port area 105opened in a given sleeve 100 to achieve any suitable treatment purpose,such as a limited entry perforation.

With an understanding of the components of the system 10, furtherdetails of a treatment operation performed with the disclosed system 10are discussed. As noted above with reference to FIG. 5, the borehole 12is lined with casing 14 having the sleeves 100A-C disposed at particularzones or areas of the formation to be treated. The casing 14 and thesleeves 100A-C can be cemented in place in the borehole 12.Alternatively, other forms of isolation, such as casing annulus packers,may be used in the open borehole 12 to isolate one zone from another.

Either way, the ports 105 on the sleeves 100A-C can communicate with theformation during treatment operations when the sleeves 100A-C are open.Opening and closing the sleeves 100A-C is discussed below. Any cementaround the exposed ports 105 when the sleeves 100A-C are opened can beremoved using standard techniques, such as jet cutting, acidizing,dissolving, breaking with pressure, etc.

To begin a treatment operation, operators deploy the motor 130 and thepacker 150 on the coiled tubing 24 down the casing 14. As shown in FIG.9A, the packer 150 deploys inside the insert 110 of one of the sleeves100 to be opened. Operators start a pump in the pumping system (22) atthe surface to operate the motor 130 and to set the packer 150 in theinsert 110 of the sleeve 100.

As shown in FIG. 9B, for example, the packer 150 is located in theinsert 110 with the locators 157. The packer 150 is then rotated by themotor 130 and is set by engaging the drag blocks 158 inside the sleeve100. As the motor 130 continues to rotate the packer's mandrel 152 whilethe drag blocks 158 hold the packer's housing 155, the packing element156 can be compressed to extend outward and engage inside the insert'sinternal surface 112.

Eventually, the motor 130 sets the packer 150 in the insert 110 so thatrotation of the motor 130 rotates the packer 150 and the insert 110together. As the set packer 150 rotates, the insert 110 on the sleeve100 rides along the internal guide 106 and opens to expose the externalports 105, as shown in FIG. 9C. As will be appreciated, because thepacker 150 is set inside of the insert 110, rotation of the packer 150by the motor 130 transmits the torque to the insert 110, turning itaround the internal guide 106 and eventually axially displacing it tothe open position. Fluid pressure in the casing 14 can be appliedagainst the set packer 150 to assist this movement of the insert 110.

Once the sleeve 100 is open, a fluid treatment can be performed.Depending on whether any other sleeves 100 downhole on the casing 14have been closed after being previously opened, then the packer 150 mayor may not remain set in the insert 110. For example, if desired, thepacker 150 may remain set in the insert 110 to at least partiallyprevent further communication of fluid treatment down the casing 14 pastthe packer 150.

Alternatively, if previously opened sleeves 100 further downhole on thecasing 14 have been closed, then it is possible to remove the packer 150from the insert 100 and proceed with treatment. To do this, operatorspull the coiled tubing 24 into tension and continue to rotate the motor130 to unset the packer 150. Any tension shoulder on the sleeve 100A isset above what is required to unset the packer 150. The packer 150 andmotor 130 may then be run further downhole away from the open ports 105of the sleeve 100, as shown in FIG. 9D, for example.

Likewise, if a lower sleeve (100) was not closed in previous operations,operators can run the motor 130 and packer 150 downhole, as shown inFIG. 9D, and can position it in a joint below. At this point, the packer150 can then be set in the casing 14 to isolate the currently openedsleeve 100 from zones further downhole on the casing 14.

Either way, operators can perform the treatment operations by pumpingfluid down the casing 14 so that the treatment fluid exits the openedports 105 on the sleeve 100 and treats the formation throughperforations, cracks, or the like in the cement (16). Alternatively,treatment can be pumped down the coiled tubing (24) and may be directedto the casing 14 and open ports 105 using any of a number of techniques,valves, and other devices. As discussion previously, for example, thesequencing valve (170: FIG. 5) disposed on the coiled tubing (24)upstream of the motor 130 may direct treatment fluid from the coiledtubing (24) into the casing 14 for passaged into the open ports 105. Inanother alternative, the motor 130 may have an internal bypass forpassage of the treatment fluid therethrough to beyond the packer 150.These and other variations can be used.

If the packer 150 has remained set in the sleeve 100 or has been setelsewhere further downhole, operators pull the coiled tubing 24 intension and unset the packer 150 with pressure maintained on the casing14. Finally, the packer 150 can be unset and moved to the next sleeve100 on the casing 14. As before, the packer 150 is located inside theinsert 110 of the next sleeve 100 so the sleeve 100 can be opened byrotation with the motor 130. The entire process is then repeated asbefore in the casing 14 to treat the desired zones.

Once treatment is completed at a particular zone, the sleeve 100 mayremain open or may be closed. For example, to close the insert 100, thepacker 150 can be pulled uphole and can be reset in the insert 110 ofthe sleeve 100 so tension can be pulled on the coiled tubing 24 to closethe insert 110 in the sleeve 100. Also, the insert 110 may include astandard profile (not shown) (e.g., a standard B shifting tool profileat the uphole end of the insert 110) or other feature so that a shiftingtool could be used to engage the insert 110 and move it closed. To beable to pull or move the insert 110 closed, the insert 110 can use aratcheted release to allow the insert 110 to be pulled closed withoutneeding to rotate along the internal guide 106.

Briefly, one example for such a ratcheted release is shown in FIG. 8B.As shown, the biased pin 117 b can be beveled so that upward movementpushes the pin 117 b out of the slot 106. The insert 110 can then beratcheted upward in the housing's bore 104 to a closed condition. Ifdesired, the sleeve 100 may also include a mechanism for limiting theclosing of the insert 110 in the sleeve 100 so the insert 110 can beheld or locked at least partially open relative to the ports 105. Aswill be appreciated, any various lock features common to sliding sleevescan be used to hold or lock the insert 110 in place.

As will be appreciated, the terms of “sliding sleeve” and “port collar”may be used interchangeably throughout as referring in general to thesame type of device. Additionally, although the sleeves have beendisclosed herein as being deployed on casing and as being cemented in aborehole, this is not strictly necessary. Instead, the sleeves can bedisposed on any suitable tubular for positioning in the well and may ormay not be cemented in place. Finally, the terms “insert” and “sleeve”may be used interchangeably throughout to refer to the movable elementwithin a housing for opening and closing fluid communication through thehousing's external ports.

Although the motor may be a milling motor operated by fluid flow througha stator and rotor arrangement, any other type of hydraulic motor can beused. Additionally, even though a hydraulically operated motor may bepreferred for the disclosed assembly, any type of motor can be used,including an electric motor, a hydraulic motor, a mud motor, a positivedisplacement motor, a Moineau motor, a Moyno® motor, a turbine typemotor, or other type of downhole motor.

Moreover, the system disclosed above of using a packer and a motor oncoiled tubing to open sliding sleeves has been specifically describedwith reference to fluid treatment. As will be appreciated with thebenefit of the present disclosure, the teachings of the system disclosedherein can be applied to any suitable operation in which a slidingsleeve can be opened (and optionally closed) using coiled tubing. As butone example, the sleeves may provide rotationally accessible windows formulti-lateral applications, or the sleeves may provide inlets and/oroutlets for any other suitable downhole application (e.g., completion,production, injection, treatment, etc.) in a borehole.

The foregoing description of preferred and other embodiments is notintended to limit or restrict the scope or applicability of theinventive concepts conceived of by the Applicants. It will beappreciated with the benefit of the present disclosure that featuresdescribed above in accordance with any embodiment or aspect of thedisclosed subject matter can be utilized, either alone or incombination, with any other described feature, in any other embodimentor aspect of the disclosed subject matter.

In exchange for disclosing the inventive concepts contained herein, theApplicants desire all patent rights afforded by the appended claims.Therefore, it is intended that the appended claims include allmodifications and alterations to the full extent that they come withinthe scope of the following claims or the equivalents thereof.

What is claimed is:
 1. A system using coiled tubing for treating aformation of a borehole having casing, the system comprising: at leastone sleeve disposed on the casing in the borehole, the at least onesleeve having at least one port communicating outside the at least onesleeve and having an insert disposed in the at least one sleeve, theinsert movable in the at least one sleeve at least from a closedposition to an opened position relative to the at least one port; amotor deployed in the casing with the coiled tubing and being operableto impart rotation; and a packer operatively coupled to the motor, thepacker, in response to the rotation imparted by the motor, engaging inthe insert of the at least one sleeve and moving the insert at least tothe opened condition.
 2. The system of claim 1, wherein the insert andthe sleeve comprise means for guiding rotation and axial displacement ofthe insert moving in the at least one sleeve at least from the closedposition to the opened position.
 3. The system of claim 1, wherein theat least one sleeve comprises an internal guide disposed thereon andguiding movement of the insert in the at least one sleeve; and whereinthe insert comprises an external guide disposed thereon and movablealong the internal guide of the at least sleeve.
 4. The system of claim3, wherein the internal guide defines a slot formed around an insidesurface of the at least one sleeve; and wherein the external guidecomprises a pin disposed on an external surface of the insert andmovable along the slot.
 5. The system of claim 1, wherein the insertrotates and displaces axially in the at least one sleeve when movingfrom the closed position to the opened position.
 6. The system of claim1, wherein the packer comprises at least one grip movable on the packerto an extended condition to engage the insert.
 7. The system of claim 1,wherein the packer comprises at least one packing element disposed onthe packer and being compressible to engage inside the insert.
 8. Thesystem of claim 1, wherein the motor comprises a hydraulic motoroperable by flow of fluid from the coiled tubing through the motor. 9.The system of claim 1, further comprising a valve in communicationbetween the coiled tubing and the motor, the valve being operable todirect fluid flow from the coiled tubing away from the motor.
 10. Thesystem of claim 1, further comprising an agitator operable to agitatethe coiled tubing.
 11. The system of claim 1, wherein the insert ismovable in the at least one sleeve from the opened position to theclosed position.
 12. The system of claim 11, wherein to move from theclosed position to the opened position, a guide component disposedbetween the at least one sleeve and the insert guides rotation and axialdisplacement of the insert in the at least one sleeve; and wherein tomove from the opened position to the closed position, the guidecomponent permits the axial displacement of the insert in the at leastone sleeve.
 13. A sleeve for fluid communication on tubing, the sleevecomprising: a housing having first and second ends coupling to thetubing and having a bore therethrough, the housing defining at least oneport communicating the bore outside the housing; an insert disposed inthe bore of the housing and being movable inside the bore at least froma closed position to an opened position relative to the at least oneport; and a guide component disposed between the housing and the insertand guiding rotation and axial displacement of the insert moving fromthe closed position to the opened position.
 14. A system using coiledtubing for treating a formation of a borehole through at least onesleeve disposed on casing in the borehole, the at least one sleevehaving an insert disposed therein, the insert movable in the at leastone sleeve at least from a closed position to an opened positionrelative to at least one port, the system comprising: a motor deployedin the casing with the coiled tubing and being operable to impartrotation; and a packer operatively coupled to the motor, the packer, inresponse to the rotation imparted by the motor, engaging in the insertof the at least one sleeve and moving the insert at least to the openedcondition with the rotation imparted by the motor.
 15. A method usingcoiled tubing for treating a formation of a borehole having casing withat least one sleeve disposed thereon, the method comprising: deploying amotor and a packer in the casing with the coiled tubing; engaging thepacker in an insert of the at least one sleeve; imparting rotation tothe packer with the motor; moving the insert of the at least one sleevefrom a closed position to an opened position with the imparted rotationof the engaged packer; and treating the formation through at least oneport of the opened sleeve.
 16. The method of claim 15, wherein engagingthe packer in the insert of the at least one sleeve comprises rotatingone portion of the packer relative to another portion of the packer andcompressing a compressible packing element on the packer against aninside surface of the insert.
 17. The method of claim 15, whereinimparting the rotation to the packer with the motor comprises pumpingfluid to the motor through the coiled tubing and rotating the packerwith the rotation from the motor.
 18. The method of claim 15, whereinmoving the insert of the at least one sleeve from the closed position tothe opened position with the imparted rotation of the engaged packercomprises guiding rotation and axial displacement of the insert with aguide component disposed between the insert and the at least one sleeve.19. The method of claim 15, further comprising unsetting the packer fromthe insert either before or after treatment.
 20. The method of claim 19,wherein unsetting the packer comprises pulling tension on the coiledtubing and imparting rotation to the packer with the motor.
 21. Themethod of claim 19, wherein, after unsetting the packer beforetreatment, the method comprises deploying the motor and the packer onthe coiled tubing downhole of the at least one port in the openedsleeve.
 22. The method of claim 19, further comprising setting thepacker in the casing downhole of the at least one port in the openedsleeve.
 23. The method of claim 15, wherein treating the formationthrough the at least one port of the opened sleeve comprises pumpingtreatment down the casing.
 24. The method of claim 15, furthercomprising moving the insert from the opened position to the closedposition in the sleeve.
 25. The method of claim 24, wherein moving theinsert from the opened position to the closed position in the sleevecomprising pulling up the insert with tension of the coiled tubing onthe engaged packer in the insert.